##### Table of Contents

**2011**

 

 

**United States**

**Securities and Exchange Commission**

**Washington, D.C. 20549**

 

**
 
**

**Form 40-F**

 

**
 
**

 

 

 

 

**
 
**

**Husky Energy Inc.**

**(Exact name of Registrant as specified in its charter)**

 

**
 
**

 

**707-8th Avenue S.W., P.O. Box 6525 Station D, Calgary, Alberta, Canada T2P 3G7**

**(403) 298-6111**

**(Address and telephone number of Registrant’s principal executive office)**

**CT Corporation System, 111 Eighth Avenue, New York, New York 10011**

**(212)894-8400**

**(Name, address (including zip code) and telephone number (including area code) of agent for service in theUnited States)**

**Securities registered or to be registered pursuant to Section 12(b) of the Act:**

**Title of Class: None**

**Securities registered or to be registered pursuant to Section 12(g) of the Act:**

**Title of Class: None**

 

**
 
**

**Securitiesfor which there is a reporting obligation pursuant to Section 15(d) of the Act:**

**Title of Class:****CommonShares******

**For annual reports, indicate by check mark the information filed with this Form:**

 

Number of outstanding shares of each of the issuer’s classes of capital or common stock as of theclose of the period covered by the annual report: 957,537,098 

Common Shares outstanding as of December 31, 2011

12,000,000 Cumulative Redeemable Preferred Shares, Series 1 outstanding as of December 31, 2011 

Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Exchange Act duringthe preceding 12 months (or for such shorter period that the Registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days.    Yes  x    No   ̈

Indicateby check mark whether the Registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (s.232.405 of this chapter) duringthe preceding 12 months (or for such shorter period that the Registrant was required to submit and post such files).    Yes   ̈    No   ̈

The Annual Report on Form 40-F shall be incorporated by reference into or as an exhibit to, asapplicable, the Registrant’s Registration Statement under the Securities Act of 1933: Form F-10 File No. 333-174554. 

 

 

 

Table of Contents
**Principal Documents**

The following documents have been filed as part of this Annual Report on Form 40-F: 

 
**A.****Annual Information Form**
The Annual Information Form of Husky Energy Inc. (“Husky” or “the Company”) for the year ended December 31, 2011is included as Document A of this Annual Report on Form 40-F. 

 
**B.****Audited Annual Financial Statements**
Husky’s audited consolidated financial statements for the years ended December 31, 2011 and December 31, 2010, including the auditors’ report with respect thereto, is included asDocument B of this Annual Report on Form 40-F. 

 
**C.****Management’s Discussion and Analysis**
Husky’s Management’s Discussion and Analysis for the year ended December 31, 2011 is included as Document C of this Annual Report on Form 40-F. 

 
**Certifications******
See Exhibits 23.1, 23.2,31.1, 31.2, 32.1 and 32.2, which are included as Exhibits to this Annual Report on Form 40-F. 

**Supplemental Reserves Information**

See Exhibit 99.1 for the Supplemental Reserves Information, which is included as an Exhibit to thisAnnual Report on Form 40-F. 

**Disclosure Controls and Procedures**

See the section “Disclosure Controls and Procedures” in Husky’s Management’s Discussion and Analysis for the yearended December 31, 2011 which is included as Document C to this Annual Report on Form 40-F. 

**Management’s Annual Report onInternal Control Over Financial Reporting**

The section “Management’s Annual Report on Internal Control overFinancial Reporting” in Husky’s Management’s Discussion and Analysis, is included as Document C to this Annual Report on Form 40-F. 

**Attestation Report of the Registered Public Accounting Firm**

Therequired disclosure is included in the “Independent Auditors’ Report of Registered Public Accounting Firm” that accompanies Husky’s consolidated financial statements for the year ended December 31, 2011, which is included asDocument B to this Annual Report on Form 40-F. 

**Changes in Internal Control Over Financial Reporting**

The required disclosure is included in the section “Disclosure Controls and Procedures” in Husky’s Management’sDiscussion and Analysis for the year ended December 31, 2011, which is included as Document C to this Annual Report on Form 40-F. 

**Notice Pursuant to Regulation BTR**

Not Applicable. 

**Audit Committee Financial Expert**

The Board of Directors of Husky has determined that William Shurniak is an “audit committee financial expert” (as defined inparagraph 8(b) of General Instruction B to Form 40-F) serving on its Audit Committee. Pursuant to paragraph 8(a)(2) of General Instruction B to Form 40-F, the Board has applied the definition of independence applicable to the audit committee membersof New York Stock Exchange listed companies. Mr. Shurniak is a corporate director and is independent under the New York Stock Exchange standards. For a description of Mr. Shurniak’s relevant experience in financial matters, seeMr. Shurniak’s history in the section “Directors and Officers” and in the section “Audit Committee” in Husky’s Annual Information Form for the year ended December 31, 2011, which is included as Document A ofthis Annual Report on Form 40-F. 

 
*Page**ii*

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**Code of Business Conduct and Ethics**

Husky’s Code of Ethics is disclosed in its Code of Business Conduct, which is applicable to its principal executive officer,principal financial officer, principal accounting officer or controller or persons performing similar functions and to all of its other employees, and is posted on its website at www.huskyenergy.com. In September 2011, Husky made amendmentsto its Code of Business Conduct to clarify that any employee that is concerned about a potential instance of non-compliance with the code is encouraged to discuss the matter with the employee’s supervisor or manager or a Human Resources advisoror report the matter through Husky’s Ethics Help Line or to specified senior executives. A copy of Husky’s Code of Business Conduct, as amended, is included as Exhibit 99.2 to this Annual Report on Form 40-F . In the fiscal year endedDecember 31, 2011, Husky has not granted a waiver including an implicit waiver from a provision of its Code of Ethics. In the event that, during Husky’s ensuing fiscal year, Husky: 

 
 i.amends any provision of its Code of Business Conduct that applies to its principal executive officer, principal financial officer, principal accounting officer orcontroller or persons performing similar functions that relates to any element of the code of ethics definition enumerated in paragraph (9)(b) of General Instruction B to Form 40-F, or 
 
 ii.grants a waiver, including an implicit waiver, from a provision of its Code of Business Conduct to any of its principal executive officer, principal financial officer,principal accounting officer or controller or persons performing similar functions that relates to one or more of the items set forth in paragraph (9)(b) of General Instruction B to Form 40-F, 
Husky will promptly disclose such occurrences on its website following the date of such amendment or waiver and will specifically describe the nature ofany amendment or waiver, and in the case of a waiver, name the person to whom the waiver was granted and the date of the waiver. 

**Principal Accountant Fees and Services**

See the section “External Auditor Service Fees” in the Annual Information Form for the year ended December 31, 2011, which is included as Document A to this Annual Report on Form 40-F.

**Off-Balance Sheet Arrangements**

See the section “Off-Balance Sheet Arrangements” in Husky’s Management’s Discussion and Analysis for the year ended December 31, 2011, which is included as Document C to thisAnnual Report on Form 40-F. 

**Tabular Disclosure of Contractual Obligations**

See the section “Cash Requirements” in Husky’s Management’s Discussion and Analysis for the year endedDecember 31, 2011, which is included as Document C to this Annual Report on Form 40-F. 

**Identification of the Audit Committee**

Husky has a separately designated standing audit committee established in accordance with Section 3(a)(58)(A) ofthe Exchange Act. The members of the audit committee are: W. Shurniak, C.S. Russel, F.S.H. Ma and G.C. Magnus. 

**Interactive Data File**

Not applicable. 

**Mine Safety Disclosure**

Not applicable. 

 
*Page**iii*

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**Undertaking and Consent to Service of Process**

**Undertaking**

Huskyundertakes to make available, in person or by telephone, representatives to respond to inquiries made by the Commission staff, and to furnish promptly, when requested to do so by the Commission staff, information relating to: the securities inrelation to which the obligation to file an annual report on Form 40-F arises; or transactions in said securities. 

**Consent to Service ofProcess**

A Form F-X signed by Husky and its agent for service of process has been filed with the Commission together withForm F-10 (333 - 174554) in connection with its common shares registered on such form. 

Any change to the name or addressof the agent for service of process of Husky shall be communicated promptly to the Commission by an amendment to the Form F-X referencing the file number of Husky. 

**Signatures**

Pursuant to the requirements of the Exchange Act, Husky EnergyInc. certifies that it meets all of the requirements for filing on Form 40-F and has duly caused this Annual Report to be signed on its behalf by the undersigned, thereto duly authorized. 

Dated this 8th day of March, 2012 

 
 **Husky Energy Inc.**
By:
 
/s/ Asim Ghosh

Name:
 Asim Ghosh
Title:
 President & Chief Executive Officer
By:
 
/s/ James D. Girgulis

Name:
 James D. Girgulis
Title:
 Vice President, Legal & Corporate Secretary
 
*Page**iv*

Table of Contents
**Document A**

**Form 40-F**

**Annual Information Form**

**For the Year Ended December 31, 2011**

Table of Contents
**Husky Energy Inc.**

**Annual Information Form**

**For the Year Ended December 31, 2011**

**March 8, 2012**

Table of Contents
**TABLE OF CONTENTS**

 

EXCHANGE RATE INFORMATION
   3  
DISCLOSURE OF EXEMPTION UNDER NATIONAL INSTRUMENT 51-101
   3  
CORPORATE STRUCTURE
   4  
Husky Energy Inc.
   4  
Intercorporate Relationships
   4  
GENERAL DEVELOPMENT OF HUSKY
   4  
Three Year History of Husky
   4  
Business Environment Trends
   7  
DESCRIPTION OF HUSKY’S BUSINESS
   8  
General
   8  
Social and Environmental Policy
   8  
Risk Factors
   10  
Upstream Operations
   15  
Disclosures of Oil and Gas Activities
   15  
Description of Major Properties and Facilities
   38  
Distribution of Oil and Gas Production
   48  
Midstream Operations
   49  
Downstream Operations
   52  
Human Resources
   55  
DIVIDENDS
   55  
DESCRIPTION OF CAPITAL STRUCTURE
   56  
MARKET FOR SECURITIES
   58  
DIRECTORS AND OFFICERS
   60  
AUDIT COMMITTEE
   68  
LEGAL PROCEEDINGS
   69  
INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS
   69  
TRANSFER AGENT AND REGISTRARS
   69  
INTERESTS OF EXPERTS
   69  
ADDITIONAL INFORMATION
   70  
ABBREVIATIONS AND GLOSSARY OF TERMS
   71  
SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS
   76  
**Schedules**
  
A – Audit Committee Mandate
   80  
B – Report on Reserves Data by Qualified Reserves Evaluator
   84  
C – Report of Management and Directors on Oil and Gas Disclosure
   85  
D – Independent Engineer’s Audit Opinion
   87  
In this Annual Information Form, the terms “Husky,” “we,” “our,”“us,” and “the Company,” means Husky Energy Inc. and its subsidiaries and partnership interests on a consolidated basis including information with respect to predecessor corporations. 

**Disclosure of Oil and Gas Information**

Unless otherwise noted in this document, all reserves estimates given have an effective date of December 31, 2011. Gross reserves or gross productionare reserves or production attributable to Husky’s interest prior to deduction of royalties; net reserves or net production are reserves or production net of such royalties. Gross or net production reported refers to sales volume, unlessotherwise indicated. Unless otherwise noted production and reserves figures are stated on a gross basis. Unless otherwise indicated, oil and gas commodity prices are quoted after the effect of hedging gains and losses. Unless otherwise indicated,all financial information is in accordance with accounting principles generally accepted in Canada. Husky completed a transition to International Financial Reporting Standards in 2011 and all 2011 and 2010 financial information has been preparedusing IFRS. Periods beginning prior to 2010 have not been restated. 

The Company uses the term barrels of oil equivalent (“boe”),which is calculated on an energy equivalence basis whereby one barrel of crude oil is equivalent to six thousand cubic feet of natural gas. Readers are cautioned that the term boe may be misleading, particularly if used in isolation. This measure isprimarily applicable at the burner tip and does not represent an equivalency at the wellhead. 

The estimates of reserves and future netrevenue for individual properties may not reflect the same confidence level as estimates of reserves and future net revenue for all properties, due to the effects of aggregation. 

 *AIF 2011*  *Page 2*
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**This Annual Information Form contains forward-looking information and statements withinthe meaning of applicable securities laws. For a full discussion of the forward-looking information and statements and the risks to which they are subject, see the “Special Note Regarding Forward-Looking Statements” in this AnnualInformation Form.**

**EXCHANGE RATE INFORMATION**

Except where otherwise indicated, all dollar amounts stated in this Annual Information Form (“AIF”) areCanadian dollars. The following table discloses various indicators of the Canadian dollar/U.S. dollar rate of exchange or the cost of a U.S. dollar in Canadian currency for the three years indicated(1) (2). 

 
   **Year ended December 31** 
*(Cdn $ per U.S. $)*
  **2011**   **2010**   **2009** 
Year end
   1.017     0.995     1.047  
Low
   0.941     0.995     1.029  
High
   1.066     1.078     1.300  
Average
   0.989     1.030     1.136  
 
(1) 
The exchange rates were as quoted by the Federal Reserve Bank of New York for the noon buying rate. 
(2) 
The high, low and average rates were either quoted or calculated as of the last day of the relevant period. 

**DISCLOSURE OF EXEMPTION UNDER NATIONAL**

**INSTRUMENT 51-101**

Husky sought and was granted by the Canadian Securities Administrators (“CSA”) an exemption from the requirement under National Instrument 51-101 “Standards of Disclosure for Oil and GasActivities” (“NI 51-101”) to involve independent qualified oil and gas reserves evaluators or auditors. Notwithstanding this exemption, the Company involves independent qualified reserves auditors as part of Husky’s corporategovernance practices. Their involvement helps assure that our internal oil and gas reserves estimates are materially correct. 

In Husky’s view, the reliability of Husky’s internally generated oil and gas reserves data is not materially different thanwould be afforded by Husky involving independent qualified reserves evaluators to evaluate and review the reserves data. The primary factors supporting the involvement of independent qualified reserves evaluators apply when (i) their knowledgeof, and experience with, a reporting issuer’s reserves data are superior to that of the internal evaluators and (ii) the work of the independent qualified reserves evaluator is significantly less likely to be adversely influenced byself-interest or management of the reporting issuer than the work of internal reserves evaluation staff. In Husky’s view, neither of these factors applies in Husky’s circumstances. 

The following oil and gas reserves disclosure has been prepared in accordance with NI 51-101 effective December 31, 2011. Prior to2010, Husky applied for and was granted an exemption from certain of the provisions of NI 51-101, which permitted the Company to present oil and gas reserves disclosures in accordance with the rules of the United States Securities and ExchangeCommission (“SEC”) and the United States Financial Accounting Standards Board (the “U.S. Rules”). This is no longer available for the Company’s reserves reporting in Canada, although the Company received approval from theCSA to also disclose its reserves using U.S. Rules as supplementary disclosure to the reserves and oil and gas activities disclosure required by NI 51-101. The reserves information prepared in accordance with the U.S. Rules is included in theCompany’s Form 40-F, which is available at www.sec.gov or on the Company’s website at www.huskyenergy.com. 

Information to further an investor’s understanding is specifically encouraged to be included in the Company’s Management’s Discussion and Analysis (“MD&A”). The MD&A isintended to be a narrative explanation describing the Company, both its history and prospects, as perceived by management. The readers of the AIF are encouraged to also read the Company’s MD&A, which is filed, in accordance with therequirements of the CSA, on the System for Electronic Data Analysis and Retrieval (“SEDAR”). Documents filed on SEDAR may be accessed online at www.sedar.com. This AIF together with the MD&A and the Company’s AuditedConsolidated Financial Statements are included in Husky’s Form 40-F which is filed with SEC’s Electronic Data Gathering Analysis and Retrieval (“EDGAR”) system, which may be accessed online at www.sec.gov. 

 *AIF 2011*  *Page 3*
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**CORPORATE STRUCTURE**

**Husky Energy Inc.**

Husky Energy Inc. was incorporated under the *Business Corporations Act*(Alberta) on June 21, 2000. The Company’s Articles were amended effective February 28, 2011 to permit theissuance of common shares as payment of stock dividends on the common shares and to authorize preferred shares to be issued in one or more series. The Company’s Articles were also amended effective March 3, 2011 to create CumulativeRedeemable Preferred Shares, Series 1 (the “Series 1 Preferred Shares”) and Cumulative Redeemable Preferred Shares, Series 2 (the “Series 2 Preferred Shares”). 

Husky Energy Inc. has its registered office and its head and principal office at 707, 8th Avenue S.W., P.O. Box 6525, Station D, Calgary,Alberta, T2P 3G7. 

**Intercorporate Relationships**

The principal subsidiaries of Husky and place of incorporation, continuance or place of organization, as the case maybe, are as follows (1). All of the following companies and partnerships, except asotherwise indicated, are 100% beneficially owned or controlled or directed, directly or indirectly. 

 

**Name**
  **Jurisdiction**
**Subsidiaries of Husky Energy Inc.**
  
Husky Oil Operations Limited (“HOOL”)
  Alberta
**Subsidiaries of Husky Oil Operations Limited**
  
Husky Oil Limited Partnership
  Alberta
Husky Terra Nova Partnership
  Alberta
Husky Downstream General Partnership
  Alberta
Husky Energy Marketing Partnership
  Alberta
Sunrise Oil Sands Partnership (50%)
  Alberta
BP Husky Refining LLC (50%)
  Delaware
Lima Refining Company
  Delaware
Husky Marketing and Supply Company
  Delaware
 
(1) 
Principal operating subsidiaries exclusive of intercorporate relationships due to financing related receivables and investments.

**GENERAL DEVELOPMENT OF HUSKY**

**Three Year History of Husky**

**2009**

In 2009, Husky completed drilling and testing of three appraisalwells at the Liwan 3-1 field on Block 29/26, in the South China Sea. 

In 2009, an application was made in the East Bawean IIProduction Sharing Contract (“PSC”) to relinquish the block. The application was based on the drilling of two exploration wells, the Adiyasa 1 and Kukura 1, which were abandoned without testing in 2009. 

Husky filed a debt shelf prospectus with the Alberta Securities Commission on February 26, 2009 and the SEC on February 27,2009. The shelf prospectus enabled Husky to offer up to U.S. $3.0 billion of debt securities in the U.S. until March 26, 2011. 

On May 11, 2009, Husky issued U.S. $750 million of 5.90% notes due June 15, 2014 and U.S. $750 million of 7.25% notes due December 15, 2019 under the debt shelf prospectus filed in February2009. 

On October 29, 2009, Husky announced it had completed and tested two exploratory wells to evaluate the shale gaspotential in the Montney and Doig formations in northeast British Columbia. 

On November 23, 2009, Husky announced thediscovery of additional oil resources in the White Rose area. 

On November 30, 2009, Husky announced an agreement topurchase Penn West Energy Trust’s heavy oil properties contained within Husky’s Lloydminster area of operations in Alberta and Saskatchewan. 

On December 8, 2009, Husky announced a significant new natural gas discovery at Liuhua 34-2-1 on Block 29/26 in the South China Sea. 

 *AIF 2011*  *Page 4*
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On December 10, 2009, Husky announced that it entered into an agreement with SuncorEnergy Inc. and Suncor Energy Products Inc. to purchase 98 retail outlets in the Ontario market. The first site was transferred to Husky in March 2010, with the remaining sites transferred between April and November 2010. 

On December 21, 2009, Husky filed a debt shelf prospectus that enabled Husky to offer up to $1.0 billion of medium term notes inCanada until January 21, 2012. 

**2010**

On January 20, 2010, Husky announced that it had completed the front end engineering design (“FEED”) for Phase I of the Sunrise Energy Project, located 60 kilometers northeast of FortMcMurray. The Company also obtained the necessary approvals from the Government of Alberta, Environment Department and the Energy Resources and Conservation Board (“ERCB”) to proceed with the project. Husky later announced in November 2010that it was moving forward with the construction of facilities for the phased development of the Sunrise oil sands lease in the Fort McMurray region of northern Alberta. This first phase is expected to cost approximately $2.5 billion and is expectedto produce approximately 60,000 barrels per day gross beginning in 2014. Further, Sunrise will use steam-assisted gravity drainage (“SAGD”) technology which limits site disturbance. In November 2010, sanction for Phase I was announced.

On February 8, 2010, Husky announced its third significant gas discovery on Block 29/26 in the South China Sea.

On March 9, 2010, Husky announced that it would issue $700 million in medium term notes under the $1 billion shelfprospectus which was filed by the Company in December 2009 with the securities regulatory authorities in each of the provinces of Canada. The medium term notes were issued in two tranches: $300 million at 3.75% maturing on March 12, 2015 and$400 million at 5.00% maturing on March 12, 2020. The transaction closed on March 12, 2010. 

On May 21, 2010,Husky announced the appointment of Mr. Asim Ghosh as President and Chief Executive Officer of the Company, effective June 1, 2010. Mr. Ghosh was previously appointed to the Board of Directors in May, 2009. The Company’s formerPresident and Chief Executive Officer, Mr. John C.S. Lau, was appointed President and Chief Executive Officer, Asia Pacific, in May 2010 after stepping down as President and Chief Executive Officer of Husky Energy Inc. after 18 years in theposition. 

On May 31, 2010, Husky completed drilling and successful testing of the first appraisal well at the Liuhua29-1 discovery Block 29/26 in the South China Sea with encouraging results. 

On May 31, 2010, Husky also announced thatoil production had been achieved from the North Amethyst field, offshore Newfoundland and Labrador. North Amethyst is the first satellite field development at Husky’s White Rose project and was brought on production less than four years afterdiscovery. It is also the first subsea tieback project in Canada. 

On September 1, 2010, Husky announced that a purchaseagreement had been signed to acquire natural gas properties in west central Alberta, which added 10.8 mboe/day of gross production, 32.9 mmboe of proved reserves and 10.7 mmboe of probable reserves, and extended the optimum utilization of its RamRiver gas plant. The acquisition also added 160,000 acres of land to the Company’s holdings, including 122,000 undeveloped acres, doubling Husky’s land holdings in the region. This purchase closed on November 30, 2010 and had aneffective date of June 1, 2010. The reserves estimates are as at December 31, 2010. 

On October 27, 2010, Huskyannounced that it had completed the successful drilling of a second appraisal well at the Liuhua 29-1 discovery Block 29/26 in the South China Sea. Additional appraisal drilling will be undertaken to further define the resource size andprepare the Plan of Development for the field once the well data has been integrated. 

On October 28, 2010, Huskyannounced that it had received approval from the Government of Indonesia for a 20 year extension to the existing Madura Strait PSC, originally awarded in 1982. The Madura Strait PSC includes the Madura BD and MDA fields, as well as numerous otherprospects and leads. Husky and its partner in the Madura Strait also agreed to sell a 10% equity stake each, in the Madura PSC to Samudra Energy Ltd., through its affiliate SMS Development Ltd. Following the completion of the sale, Husky and ChinaNational Offshore Oil Corporation (“CNOOC”) respectively hold a 40% equity interest in Husky Oil (Madura) Limited, with the remaining 20% held by Samudra Energy Ltd. This sale closed on January 13, 2011 and subsequently Husky Oil(Madura) Ltd. has changed its name to Husky-CNOOC Madura Ltd. 

Effective November 26, 2010, Husky filed a universal shortform base shelf prospectus with applicable securities regulators in each of the provinces of Canada. The shelf prospectus enables Husky to offer up to $3 billion of common shares, preferred shares, debt securities, subscription receipts, warrantsand units in Canada until December 2012. 

 *AIF 2011*  *Page 5*
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Husky signed an $860 million purchase and sale agreement to acquire oil and natural gasproperties in Alberta and northeast British Columbia. This purchase included 16.3 mboe/day of gross natural gas production, 4.8 mbbls/day of gross oil production, and 0.8 mbbls/day of natural gas liquids (“NGL’s”). Husky estimatedreserves acquired of 104 mmboe of proved reserves and nine mmboe of probable reserves based on an effective date of December 1, 2010. The purchase transaction closed on February 4, 2011. 

Husky also announced that it decided to retain its Asia Pacific assets citing the Company’s view that it is in the best interest ofthe shareholders to continue to build this material business in the resource-rich region and leverage the close proximity to major energy markets in Hong Kong and Mainland China. 

The Government of China approved the Original-Gas-in-Place (“OGIP”) report for the Liwan 3-1 field. Tendering for majorequipment and facilities is underway and key contracts are expected to be awarded in the near term in order to achieve first gas production in late 2013. 

On December 7, 2010 Husky issued equity by way of a public overnight-marketed common share offering and a private placement to its principal shareholders. Pursuant to the public offering, the Companyissued a total of 11.9 million common shares at a price of $24.50 per share for total gross proceeds of approximately $293 million. The public offering was conducted under the Company’s previously filed shelf prospectus and supplement tothe shelf prospectus. The Company also issued a total of 28.9 million common shares to the principal shareholders, L.F. Investments (Barbados) Limited and Hutchison Whampoa Luxembourg Holdings S.à.r.l. at a price of $24.50 per share fortotal gross proceeds of approximately $707 million via a private placement. The public offering and private placement closed on December 7, 2010. 

On December 7, 2010, Husky announced that it had signed a Heads of Agreement with CNOOC, specifying the key principles of cooperation for funding and operation of the Liwan 3-1 deep water gas fielddevelopment. Under the agreement for the Liwan 3-1 field development, Husky will operate the deep water portion of the project involving development drilling and completions, subsea equipment and controls, and subsea tie-backs to a shallow waterplatform. CNOOC will operate the shallow water portion of the project including a shallow water platform, approximately 270 kilometers of subsea pipeline to shore, and the onshore gas processing plant. 

**2011**

OnFebruary 28, 2011, Husky announced that its shareholders voted in favour of an amendment to the Company’s Articles, which will allow shareholders to accept dividends in cash or in common shares. The shareholders also approved an amendmentto allow for the issuance of preferred shares. 

On March 18, 2011, Husky issued 12 million Series 1 Preferred Sharesat a price of $25.00 per share for aggregate gross proceeds of $300 million. Holders of the Series 1 Preferred Shares are entitled to receive a cumulative quarterly fixed dividend yielding 4.45% annually for the initial period ending March 31,2016. Thereafter, the dividend rate will be reset every five years at a rate equal to the 5-year Government of Canada bond yield plus 1.73%. Holders of Series 1 Preferred Shares will have the right, at their option, to convert their shares intoSeries 2 Preferred Shares, subject to certain conditions, on March 31, 2016 and on March 31 every five years thereafter. Holders of the Series 2 Preferred Shares will be entitled to receive cumulative quarterly floating rate dividends at arate equal to the three-month Government of Canada Treasury Bill yield plus 1.73%. 

On June 13, 2011, Husky filed auniversal short form base shelf prospectus with the Alberta Securities Commission and the SEC. The prospectus will enable Husky to offer up to U.S. $3 billion of common shares, preferred shares, debt securities, subscription receipts, warrants andunits in the United States until July 13, 2013. 

On June 29, 2011, Husky completed a $1 billion public offering anda $200 million private placement to its principal shareholders, L.F. Investments (Barbados) Limited and Hutchison Whompoa Luxembourg Holdings S.a.r.l. The Company issued approximately 37 million common shares at $27.50 per share in the publicoffering and approximately 7 million common shares at a price of $27.50 per share in the private placement. The public offering was made pursuant to a prospectus supplement to the Company’s universal base shelf prospectus filedNovember 26, 2010 with the securities regulatory authorities in all provinces of Canada and to the Company’s universal base shelf prospectus filed June 13, 2011, with the Alberta Securities Commission and the SEC. 

On September 19, 2011, Husky announced that it had sanctioned the development of the Liwan 3-1 and Liuhua 34-2 fields, the principalfields of the Liwan Gas Project in the South China Sea. The project, which is being jointly developed by Husky and CNOOC, aims to bring at least three natural gas discoveries on Block 29/26 to market. The Overall Development Plan (“ODP”)for Liwan 3-1 was submitted to the Chinese government authorities for regulatory approval and a gas sales agreement for production from the field is in place. The gas sales agreement was executed with CNOOC Gas & Power Group, GuangdongBranch for volumes from the Liwan 3-1 field. Production from the field will supply the Guangdong Province natural gas grid from an onshore gas plant at Gaolan Island, Zhuahai. 

 *AIF 2011*  *Page 6*
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**Business Environment Trends**

There are a number of trends that are developing that may have both short and long-term effects on the oil and gas industry in Canada.Production from oil sands projects are expected to continue to accelerate as the dominant source of crude oil product in the decades to come. During 2010, production of bitumen from oil sands from both mining and in-situ operations increased by 9%compared with 2009. Non-upgraded bitumen and synthetic crude oil from oil sands accounted for 52% of Canadian production in 2010, an increase of 2% from 2009. Production of crude oil, including bitumen and synthetic crude oil, was 5% higher in 2010compared with 2009. From 2004 to 2010, conventional crude oil production replacement in Canada averaged 85%(1). In its June 2011 forecast, the Canadian Associationof Petroleum Producers (“CAPP”) projected total Canadian production to increase by approximately 67% to 4.7 mmbbls/day by 2025, of which 3.7 mmbbls/day would be from oil sands. Production above 3.3 mmbbls/day would be sourced from new oilsands projects that were not under construction at the forecast date. In addition, the decade long decline in conventional crude oil production was effectively halted in 2010. This resulted from the application of new technologies in resource playsin Western Canada such as horizontal wells combined with multi-stage fracturing and by favourable royalty amendments by the Government of Alberta(2). 

During 2011, natural gas production in Canada continued to decline while production in the United States increased by an estimated 4.8 bcf/day over the previous year. Ample natural gas supply and highstorage levels have resulted in continued low prices. Although the natural gas rig count has declined, natural gas markets are expected to remain well supplied in the near-term as a backlog of shale gas wells near markets in the U.S. Gulf Coast,mid-continent and eastern states continue to be completed and tied-in. As a result, investment in Canadian natural gas exploration and development is expected to be focused on resource plays that utilize new technology and are in natural gas liquidprone areas(3). Conventional natural gas exploration isexpected to be focused on the traditionally less accessible areas in the overthrust belt along the eastern slope of the Rocky Mountains. 

The trend of volatile commodity prices is expected to continue. Natural gas prices are sensitive to regional supply and demand imbalances, regional industrial activity levels, weather patterns and accessto cheaper sources of energy. Oil prices are subject to potential supply disruptions and increased demand from emerging economies. Notwithstanding supply disruptions or major policy changes in respect of greenhouse gas emissions, recent forecasts(4) by the Energy Information Administration(“EIA”) in the United States include significant long-term potential for increased crude oil supply from producers outside of the Organization of the Petroleum Exporting Countries (“OPEC”) over the next two and a half decades,particularly conventional production from Brazil, Russia, and Kazakhstan and further investment in exploration. Also, with the economic viability of Canada’s oil sands supported by rising world oil prices and advances in production technology,Canadian oil sands production is projected by the EIA to reach 5.0 mmbbls/day in 2035. World oil prices declined in the second half of 2008 from their mid-July peak and trended upward through 2009, 2010 and 2011. By February 7, 2012, West TexasIntermediate (“WTI”) spot prices had averaged U.S. $99.75/bbl and Brent spot averaged U.S. $111.25/bbl during the first few weeks of 2012. The EIA’s reference case forecasts prices to gradually rise as the world economy recovers andglobal demand grows more rapidly than crude oil supplies from non-OPEC producers. 

Transportation and market access in NorthAmerica for crude oil emerged as a major issue in 2011, contributing to regional price volatility. Crude oil with access to water borne transportation receives a higher Brent based price, due to its increased mobility, compared to on-shore NorthAmerican crude which is valued based on WTI pricing. Most western Canadian, on-shore crude is transported to Cushing, Oklahoma where the price for WTI is set. For most of 2011, Cushing was oversupplied with crude as a result of limited capacityto transport crude to US Gulf Coast refineries and from an increase of on-shore production from emerging resource plays like the North Dakota Bakken and Canadian oil sands, increasing the price differential between Brent crude and WTI crude. Thereare several transportation projects under development or being considered that could help reduce the crude price disparity in the longer term such as the Seaway Pipeline reversal, Wrangler Pipeline, Keystone XL Pipeline, Northern Gateway Pipelineand Trans Mountain Pipeline expansion, however considerable uncertainty exists on when and if each of these solutions will be in service. 

The EIA Short-Term Energy Outlook(5) was published on February 7, 2012 and provides the following insights to the near-term energy environment. World energy demand is expected to continue to increase in 2012 and 2013, mostly incountries outside of the Organization for Economic Cooperation and Development (“OECD”). World liquid fuels consumption grew by 1% to reach 87.9 mmbbls/day in 2011 and is expected to grow by 1.5% per year in 2012 and 2013. Modestgrowth in consumption in the United States and Japan is expected to be more than offset by lower consumption in Europe over the next two years. OPEC’s spare capacity is expected to rise from 2.2 mmbbls/day in December 2011 to 3.9 mmbbls/day bythe end of 2013. 

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There are many significant uncertainties that could result in higher or lower oil prices.Should a significant oil supply disruption occur, and OPEC members fail to increase production or anticipated non-OPEC oil developments are delayed, oil prices could be significantly higher than projected. If the pace of economic recovery fails toaccelerate in OECD countries or if economic growth slows in non-OECD countries, reduced demand could result in lower prices. 

 
(1) 
“Canadian Energy Overview 2010”, July 2011, National Energy Board. 
(2) 
“Crude Oil Forecast, Markets and Pipelines”, June 2011, Canadian Association of Petroleum Producers. 
(3) 
“Winter Energy Outlook 2011 – 2012 Adjusting to Economic Uncertainty”, November 2011, National Energy Board.
(4) 
“Annual Energy Outlook 2012 Early Release Overview”, January 23, 2012, Energy Information Administration U.S. Department of Energy.
(5) 
“Short-Term Energy Outlook,” February 7, 2012, Energy Information Administration U.S. Department of Energy.

**DESCRIPTION OF HUSKY’S BUSINESS**

**General**

Husky is a publicly traded integrated international energy company headquartered in Calgary, Alberta, Canada. 

Husky’s business is conducted predominantly in three business segments - Upstream, Midstream and Downstream. 

Upstream includes exploration for, development and production of crude oil, bitumen, natural gas and natural gas liquids. The Company’s Upstream operations are located primarily in Western Canada,offshore Eastern Canada, offshore Greenland, offshore China, and offshore Indonesia. 

Midstream includes marketing of theCompany’s and other producers’ crude oil, bitumen, natural gas, natural gas liquids, sulphur and petroleum coke, pipeline transportation and processing of heavy crude oil and natural gas, storage of crude oil, diluents and natural gas andcogeneration of electrical and thermal energy (infrastructure and marketing). 

Downstream includes upgrading of heavy crudeoil feedstock into synthetic crude oil (upgrading), refining in Canada of crude oil and marketing of refined petroleum products including gasoline, diesel, ethanol blended fuels, asphalt and ancillary products, and production of ethanol (Canadianrefined products) and refining in the U.S. of primarily crude oil to produce and market gasoline, jet fuel and diesel fuels that meet U.S. clean fuels standards (U.S. refining and marketing). 

In the first quarter of 2011, the Company commenced evaluating and reporting its upgrading activities as part of Downstream operations.As a result, upgrading was moved from the Midstream segment to the Downstream segment. All prior periods have been reclassified to conform to these segment definitions. 

During the first quarter of 2012, the Company began evaluating and reporting the activities of the Midstream segment as a service provider to the Upstream and Downstream operations. Executive managementhas organized their assessment of the services of the Midstream segment and allocated such activities to the Company’s core exploration and production, upgrading and refining businesses. This integration is consistent with the Company’sstrategic view of its business. In addition, the Company believes this change in segment presentation allows management and third parties to more effectively assess its performance against industry peers, who have similar approaches to evaluatingand reporting their midstream operations. As a result, commencing in 2012, the segmented financial information for activities within the previously reported Midstream segment will be presented under the Upstream and Downstream segments to align withhow the Company’s results are assessed by management. 

**Social and Environmental Policy**

Husky approaches social responsibility and sustainable development by seeking a balance among economic, operationalreliability, health, safety, environmental and social issues while maintaining growth. Husky strives to find solutions to these issues that do not compromise the needs of future generations. In 2008, Husky implemented the Husky Operational IntegrityManagement System (“HOIMS”) which is followed by all Husky businesses, with particular emphasis on projects and operations and management of the operational integrity of assets throughout its life cycle. HOIMS includes 14 fundamentalelements; each element contains well defined objectives and expectations that guide Husky to continuously improve operational integrity performance outlining the overall intent behind each element and the individual activities that are undertaken tosupport these objectives. HOIMS is designed to guide Husky’s employees in effectively managing the risks associated with Husky’s business while creating a safe and secure place to work. Resources are applied and dedicated to the continuedimplementation and execution of HOIMS, and progress is monitored at all levels of the Company. Periodic reviews and audits are conducted to help ensure that HOIMS is effectively integrated into daily operations. 

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The fundamental elements of HOIMS are: 

 
 1.Ensure all levels of management demonstrate leadership and commitment to operational integrity. Define and ensure appropriate accountability for HOIMS throughout theorganization. 
 
 2.Prevent incidents by identifying and minimizing workplace and personal health risks. Promote and reinforce all safe behaviours. 
 
 3.Manage risks by performing comprehensive risk assessments to provide essential decision-making information. Develop and implement plans to manage significant risks andimpacts to as low as reasonably practical levels. 
 
 4.Be prepared for an emergency or security threat. Identify all necessary actions to be taken to protect people, the environment, the organization’s assets andreputation in the event of an emergency or security threat. 
 
 5.Maintain operations reliability and integrity by use of clearly defined and documented operational, maintenance, inspection and corrosion programs. Seek improvements inprocess and equipment dependability by systematically eliminating defects and sources of loss. 
 
 6.Provide assurance that personnel possess the necessary competencies, knowledge, abilities and behaviours to perform and demonstrate designated tasks andresponsibilities effectively, efficiently and safely. 
 
 7.Report and investigate all incidents. Learn from incidents and use the information to take corrective action and prevent recurrence. 
 
 8.Operate responsibly to minimize the environmental impact of operations. Leave a positive legacy behind when operations cease. 
 
 9.Ensure that risks and exposures from proposed changes are identified, evaluated and managed to remain at an acceptable level. 
 
 10.Identify, maintain and safeguard important information. Ensure personnel can readily access and retrieve information. Promote and encourage constructive dialogue withinthe organization to share industry recommended practices and acquired knowledge. 
 
 11.Ensure conformance with Corporate policies and compliance with all relevant government regulations. Work constructively to influence proposed laws and regulations, anddebate on emerging issues. 
 
 12.Design, construct, commission, operate and decommission all assets in a healthy, safe, secure, environmentally sound, reliable and efficient manner.
 
 13.Ensure contractors and suppliers perform in a manner that is consistent and compatible with Husky’s policies and business performance standards. Ensure contractedservices and procured materials meet the requirements and expectations of Husky’s standards. 
 
 14.Confirm that HOIMS processes are implemented and assess whether they are working effectively. Measure progress and continually improve towards meeting HOIMS objectives,targets, and key performance indicators. 
**Health, Safety and Environment**

The Health, Safety and Environment Committee of the Board of Directors is responsible for reviewing and recommending for approval by theBoard of Directors updates to the health, safety and environment policy and the development with management and achievement of specific environmental objectives and targets, and for monitoring compliance with the Company’s environmentalpolicies and regulatory requirements. The mandate of the Health, Safety and Environment Committee is available on the Husky website at www.huskyenergy.com. 

**Environmental Protection**

Husky’s operations are subject to variousenvironmental requirements under federal, provincial, state and local laws and regulations, as well as international conventions. These laws and regulations cover matters such as air emissions, wastewater discharge, freshwater use, land disturbancesand handling and disposal of waste materials. These laws and regulations have proliferated and become more complex over time, governing an increasingly broad aspect of the industry’s mode of operating and product characteristics. Huskycontinues to monitor emerging environmental laws and regulations and proactively implements programs as required for compliance. According to the American Petroleum Institute, the oil and gas industry has invested over U.S. $209 billion since 1990toward 

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improving the environmental performance of its products, facilities and operations. In 2009, the refining sector accounted for 63% and the upstream sector accounted for 24% of total oil and gasindustry environmental expenditures in the United States. In 2009, just over half of the industry’s environment expenditures were directed toward reducing emissions into the atmosphere. (1)

Husky is required by the Government of Canada to report facilities that emit greater than 50,000 tonnes of carbon dioxide equivalence (“CO2E”). The Lloydminster Upgrader, Lloydminster Refinery, Prince George Refinery, SeaRose floating, production andstorage offloading vessel (“FPSO”), Ram River gas plant, Rainbow Lake gas plant, Tucker thermal oil plant, Bolney SAGD thermal plant, Pikes Peak CSS thermal plant and the Lloydminster and Minnedosa ethanol plants are in this category.Husky has implemented an Environmental Performance Reporting System (“EPRS”) that will gather, consolidate, calculate, report and identify trends including greenhouse gas emissions. 

Husky is also a member of the Integrated Carbon Dioxide (“CO2”) Network, which is working to reduce greenhouse gas emissions. Thegroup continues to study technologies related to the capture, transportation and storage of CO2. A project is underway at Husky to capture, compress and liquefy CO2from the Lloydminster ethanol plant for injection into heavy oil fields for Enhanced Oil Recovery. At Lloydminster and Rainbow Lake, Husky utilizes cogeneration to produce bothelectricity and thermal energy for use at its processing facilities. This configuration has less adverse effects on the environment and is cost effective. Electrical energy in excess of Husky’s requirements is sold into the grid. AtHusky’s Tucker SAGD project vapour recovery systems are in use on all tanks and process vessels. 

Husky has undertaken programs to minimize water consumption, particularly freshwater, and minimize risk to waterresources. At the Tucker project, 90% of water is recycled and very saline (i.e. non-potable) water is used for make-up water. Husky is implementing various technologies to reduce water usage. Husky’s alkaline surfactant polymer floods(“ASP”), which increases the efficiency of water and the use of CO2 to mobilize heavy oil in the reservoir are being evaluated in pilots to reduce overall water consumption. 

Ongoing remediation and reclamation work is occurring at approximately 2,680 well sites and facilities. In 2011, Husky spent $105 million on remediation activities and expects to spend approximately $116million in 2012 on environmental remediation. 

At December 31, 2011, Husky had 549 retail locations in its light refinedproducts operations, which consisted of 396 owned or leased locations (Husky controlled) and 153 independent retailer locations. Husky is continually monitoring the owned and leased locations for environmental compliance and, where required,performing remediation including routine underground tank replacements. Husky has several “legacy” (inactive facility) sites which require remediation. These inactive sites range from refinery sites to retail locations. 

It is not possible to predict with certainty the amount of additional investment in new or existing facilities required to be incurred inthe future for environmental protection or to address regulatory compliance requirements, such as reporting. Although these costs may be significant, Husky does not expect that they will have a material adverse effect on liquidity and financialposition over the long-term. 

 
(1) 
“Environmental Expenditures by the U.S. Oil and Natural Gas Industry,” 2011, American Petroleum Institute. 

**Risk Factors**

The following factors should be considered in evaluating Husky: 

**Adequacy of crude oil andnatural gas prices**

Husky’s results of operations and financial condition are dependent on the prices received for itscrude oil and natural gas production. Lower prices for crude oil and natural gas could adversely affect the value and quantity of Husky’s oil and gas reserves. Husky has significant quantities of heavier grades of crude oil reservesthat trade at a discount to light crude oil. Heavier grades of crude oil are typically more expensive to produce, process, transport and refine into high value refined products. Refining and transportation capacity for heavy crude oil islimited and planned increases of North American heavy crude oil production may create the need for additional heavy oil refining and transportation capacity. As a result, wider price differentials could have adverse effects on financial performanceand condition, reduce the value and quantities of Husky’s heavier crude oil reserves and delay or cancel projects that involve the development of heavier crude oil resources. There is no guarantee that planned pipeline development projects willprovide sufficient transportation capacity and access to refining capacity to accommodate expected increases in North American heavy crude oil production. 

Prices for crude oil are based on world supply and demand. Supply and demand can be affected by a number of factors including, but not limited to, actions taken by OPEC, non-OPEC crude oil supply, socialconditions in oil producing countries, the occurrence of natural disasters, general and specific economic conditions, prevailing weather patterns and the availability of alternate sources of energy. 

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Husky’s natural gas production is located entirely in Western Canada and is, therefore,subject to North American market forces. North American natural gas supply and demand is affected by a number of factors including, but not limited to, the amount of natural gas available to specific market areas either from the well head or fromstorage facilities, prevailing weather patterns, the price of crude oil, the U.S. and Canadian economies, the occurrence of natural disasters and pipeline restrictions. 

**Demand for Husky’s other products and services and the cost of required inputs**

Husky’s results of operations and financial condition are dependent on the price of refinery feedstock, the price of energy, the demand and pricing for refined petroleum products and electrical powerand the ability of Husky to recover the increased cost of these inputs from the customer. Husky is also dependent on the demand for pipeline and processing capacity. 

**Reserves data and future net revenue estimates**

The reserves data in thisAnnual Information Form represent estimates only. In general, estimates of economically recoverable crude oil and gas reserves and the future net cash flows there from are based upon a number of variable factors and assumptions, such as productprices, future operating and capital costs, historical production from the properties and the assumed effects of regulation by governmental agencies, including with respect to royalty payments, all of which may vary considerably from actual results.All such estimates are to some degree uncertain and classifications of reserves are only attempts to define the degree of uncertainty involved. For those reasons, estimates of the economically recoverable oil and gas reserves attributable to anyparticular group of properties, classification of such reserves based on risk of recovery and estimates of future net revenues expected there from, prepared by different engineers or by the same engineers at different times, may vary substantially.

**Additions to reserves are required to maintain asset value and production**

In order to maintain the Company’s future production of crude oil, natural gas and natural gas liquids and maintain the value of thereserves portfolio, additional reserves must be added through discoveries, extensions, improved recovery, performance related revisions and acquisitions. The production rate of oil and gas properties tends to decline as the reserves are depletedwhile the associated unit operating costs increase. In order to prevent this, the Company must undertake successful exploration and development programs, increase the recovery factor from existing properties through applied technology and identifyand execute strategic acquisitions of proved developed and undeveloped properties and unproved prospects. Maintaining an inventory of developable projects depends on, among other things, obtaining and renewing rights to explore, develop and produceoil and natural gas, drilling success, completing long-lead time capital intensive projects on budget and on schedule and the application of successful exploitation techniques on mature properties. 

**Competition**

The energyindustry is highly competitive with respect to gaining access to the resources required to increase oil and gas reserves and production and gain access to markets. Husky competes with others to acquire prospective lands, to retain drilling capacityand field operating and construction services, to attract and retain experienced skilled management and oil and gas professionals, to obtain sufficient pipeline and other transportation capacity, to gain access to and retain adequate markets for itsproducts and services and gain access to capital markets. Husky’s ability to successfully complete development projects could be adversely affected if it is unable to acquire economic supplies and services due to competition. Subsequentincreases in the cost of or delays in acquiring supplies and services could result in uneconomic projects. Husky’s competitors comprise all types of energy companies, some of which have greater resources. 

**Delays and cost overruns of capital projects**

Husky is involved in capital projects such as exploration programs, development of oil and gas properties, plant and facilities construction, expansion and modification. Project delays can adverselyaffect expected cash flow and overall project costs thereby eroding project economics. Risk factors include, but are not limited to: 

 
 • 
availability and cost of capital; 

 
 • 
availability of skilled labour; 

 
 • 
availability of manufacturing capacity, supplies, material and equipment; 

 
 • 
regulatory approvals; 

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faulty construction and design errors; 

 
 • 
accidents, labour disruptions, bankruptcies and productivity issues affecting Husky directly or indirectly; and 

 
 • 
unexpected changes in the scope of a project. 

**Foreign exchange risk**

Husky’s results are affected by the exchangerate between the Canadian and U.S. dollar. The majority of expenditures are in Canadian dollars. The majority of revenues are received in U.S. dollars or from the sale of oil and gas commodities that receive prices determined by reference to U.S.benchmark prices. An increase in the value of the Canadian dollar relative to the U.S. dollar will decrease the revenues received from the sale of oil and gas commodities. Correspondingly, a decrease in the value of the Canadian dollar relative tothe U.S. dollar will increase the revenues received from the sale of oil and gas commodities. 

In addition, a change in thevalue of the Canadian dollar against the U.S. dollar will result in an increase or decrease in the costs in Canadian dollars associated with Husky’s U.S. dollar denominated debt. At December 31, 2011, 82% or $3.1 billion of Husky’slong-term debt was denominated in U.S. dollars. The percentage of long-term debt exposed to the U.S./Cdn exchange rate decreases to 73% when cross currency swaps are included. Additionally, U.S. $1.3 billion of the Company’s U.S. dollardenominated debt has been designated as a hedge of a net investment, further reducing the long-term debt exposed to the U.S./Cdn exchange rate to 27%. 

The Company holds 50% of a contribution receivable representing BP’s obligation to fund capital expenditures related to the Sunrise Oil Sands Project. The receivable is denominated in U.S. dollarsand gains and losses from changes in the value of the Canadian dollar versus the U.S. dollar are recorded in net foreign exchange gains and losses in the current period earnings. At December 31, 2011, Husky’s share of the balance of thisreceivable was U.S. $1.1 billion including accrued interest. Husky has an obligation to fund capital expenditures of the BP-Husky Toledo Refinery and this contribution payable is denominated in U.S. dollars. Gains and losses from the translation ofthis obligation are recorded in other comprehensive income in the Statement of Comprehensive Income as this item relates to a U.S. dollar functional currency foreign operation. At December 31, 2011, Husky’s share of the balance of thisobligation was U.S. $1.4 billion including accrued interest. 

**Operational risks and hazards**

Husky’s businesses are subject to inherent operational risks and hazards in respect of safety and the environment that requirescontinuous vigilance. The Company seeks to minimize these operational risks and hazards by carefully designing and building its facilities and conducting its operations in a safe and reliable manner. However, failure to manage these operationalrisks and hazards effectively could result in unexpected incidents, including releases of restricted substances, explosions, marine catastrophe or mechanical failures resulting in personal injuries, loss of life, environmental damage, propertydamage, loss of revenues, legal liability and/or disruption to operations. The Company, in accordance with industry practice, maintains insurance coverage against losses from certain of these risks and hazards. Nonetheless, insurance proceeds maynot be sufficient to cover all losses. Insurance coverage might not remain available for all types of operational risks and hazards at reasonable rates. 

**Environmental regulation**

All phases of the oil and natural gas businessare subject to environmental regulation pursuant to a variety of federal, provincial, state and local laws and regulations, as well as international conventions (collectively, “environmental legislation”). 

Environmental legislation imposes, among other things, restrictions, liabilities, and obligations in connection with the generation,handling, storage, transportation, treatment and disposal of hazardous substances and waste and in connection with spills, releases and emissions of various substances to the environment. Environmental legislation also requires that wells,facilities and other properties associated with Husky’s operations be operated, maintained, abandoned and reclaimed to the satisfaction of applicable regulatory authorities. In addition, certain types of operations, including exploration anddevelopment projects and significant changes to certain existing projects, may require the submission and approval of environmental impact assessments. Compliance with environmental legislation can require significant expenditures and failure tocomply with environmental legislation may result in the imposition of fines and penalties and liability for clean-up costs and damages. Husky believes it is in material compliance with current environmental legislation. 

Husky anticipates that changes in environmental legislation may require reductions in emissions from its operations and result inincreased capital expenditures. Further changes in environmental legislation could occur, which may result in stricter standards and enforcement, larger fines and liability, and increased capital expenditures and operating costs, which could have amaterial adverse effect on our financial condition and results of operations. 

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The Deepwater Horizon oil spill in the Gulf of Mexico has led to numerous public andgovernmental expressions of concern about the safety and potential environmental impact of offshore oil operations. Stricter regulation of offshore oil and gas operations has already been implemented in the Gulf of Mexico. Further regulation,increased financial assurance requirements and increased caps on liability are likely to be applied to offshore oil and gas operations in the Gulf of Mexico. In the event that similar changes in environmental regulation occur with respect toHusky’s operations in the Atlantic or Asia Pacific Regions, such changes could increase the cost of complying with environmental regulation in connection with these operations and have a material adverse impact on Husky’s operations.

Husky continues to monitor the international efforts to address climate change, including developments on the Kyoto Protocoland the Copenhagen Accord. Canada has withdrawn from participation in the Kyoto Protocol. The effect of these initiatives on the Company’s operations cannot be determined with any certainty at this time. The Federal Government of Canada hasannounced certain regulations in respect of greenhouse gases and other pollutants. Although the impact of these regulations is uncertain, they may adversely affect the Company’s operations and increase costs. These regulations may become moreonerous over time as public and political pressures increase to implement initiatives that further reduce the emission of greenhouse gases. 

The United States Environmental Protection Agency (“EPA”) has promulgated the so-called ‘Tailoring Rule’, which, beginning January 2, 2011, phases in over time restrictions ongreenhouse gas emissions from stationary sources, including power plants and petroleum refineries, beginning with the largest emitters, where such sources are required to obtain a new or modified permit based on non-greenhouse gas emissions. The EPAhas also promulgated regulations that require data collection and reporting of greenhouse gas emissions from stationary sources in the oil and gas industry. This reporting requirement applies to Husky’s U.S. operations. While these EPAregulations are currently in effect, they have not yet had a material impact on Husky. Husky’s operations may be impacted by future United States greenhouse gas legislation applying to the oil and gas industry or the consumption of petroleumproducts or by these or any further restrictive regulations issued by the EPA. Such legislation or regulation could require Husky’s U.S. refining operations to significantly reduce emissions and/or purchase allowances, which may increasecapital and operating expenditures. 

**Changes to government fiscal policy**

All of Husky’s oil and gas production is subject to royalties which are potentially impacted by changes in government fiscalpolicies. The Company maintains close contact with governments in the areas within which it operates. 

**General economic conditions**

General economic conditions may have a material adverse effect on the Company’s results of operations, liquidity andfinancial condition. A decline in economic activity will reduce demand for petroleum products and adversely affect the price the Company receives for its commodities. The Company’s cash flow could decline, assets could be impaired, futureaccess to capital could be restricted and major development projects could be delayed or abandoned. 

**Cost or availability of oil and gasfield equipment**

The cost or availability of oil and gas field equipment adversely affects the Company’s ability toundertake exploration, development and construction projects. The oil and gas industry is cyclical in nature and is prone to shortages of supply of equipment and services including land and offshore drilling rigs, land and offshore geological andgeophysical services, engineering and construction services and construction materials. These materials and services may not be available when required at reasonable prices. 

**International operations**

International operations can expose the Companyto uncertain political, economic and other risks. The Company’s operations in certain jurisdictions may be adversely affected by political, economic or social instability or events. These events may include, but are not limited to, acts of war,terrorism, abduction, expropriation, onerous fiscal policy, renegotiation or nullification of agreements, imposition of onerous regulation, financial constraints and unreasonable taxation. This could adversely affect the Company’s interest inits foreign operations and future profitability. 

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**Climatic conditions**

Climatic conditions may have significant adverse effects on operations. Demand for energy is affected to a large degree by weather and climate. In addition, the Company’s exploration, production andconstruction operations or disruptions to the operations of major customers or suppliers can be affected by extreme weather, which may result in cessation or diminishment of production, delay of exploration and development activities or delay ofplant construction. All of these could potentially cause financial losses. 

**Recruitment, retention and succession**

Failure to retain current employees and attract new skilled employees could materially affect the Company’s ability to conduct itsbusiness. Demand for qualified employees with appropriate experience remains high and may increase as a significant portion of the global workforce reaches retirement age in the near term. 

**Market access**

The Company’s results depend upon the Company’sability to deliver products to the most attractive markets. These results could be impacted due to lack of pipeline or other transportation alternatives, regulatory or other barriers. The Company seeks to minimize these risks by committing tomultiple pipeline alternatives, maintaining proprietary storage access, pursuing new markets and utilizing a diverse market portfolio. 

**Credit rating risk**

TheCompany’s debt instruments are rated by various credit rating agencies. These ratings affect the Company’s ability to gain access to debt financing at attractive terms. If any of the Company’s credit rating agencies downgrade theCompany’s debt instruments it may restrict the Company’s ability to issue debt and may also increase the cost of borrowing, including under existing credit facilities. 

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**Upstream Operations**

**Disclosures of Oil and Gas Activities**

***Production History***

 

**Average Gross Daily Production:**
  **Year Ended**   **Three Months Ended**    **Dec 31, 2011**   **Dec 31, 2011**   **Sept 30, 2011**   **June 30, 2011**   **Mar 31, 2011** 
**Canada – Western Canada**
          
Light crude oil and NGL (mbbls/day)
   24.8     28.8     22.9     21.7     25.9  
Medium Crude Oil (mbbls/day)
   24.5     24.3     24.6     24.6     24.6  
Heavy crude oil (mbbls/day)
   74.5     75.8     75.1     73.6     73.4  
Bitumen (mbbls/day)
   24.7     27.4     23.6     23.6     24.2  
Natural gas (mmcf/day)
   607.0     597.9     614.7     631.8     583.3  
**Canada – Atlantic Region**
          
Light crude oil (mbbls/day)
   54.3     54.6     53.4     53.7     55.5  
**China**
          
Light crude oil and NGL (mbbls/day)
   8.5     8.3     7.0     9.1     9.6    
 

 
   
 

 
   
 

 
   
 

 
   
 

 
 
**Total gross production (mboe/day)**
  ** ****312.5****  **  ** ****318.9****  **  ** ****309.1****  **  ** ****311.6****  **  ** ****310.4****  **  
 

 
   
 

 
   
 

 
   
 

 
   
 

 
 
**Average Gross Daily Production:**
  **Year Ended**   **Three Months Ended**     **Dec 31, 2010**   **Dec 31, 2010**   **Sept 30, 2010**   **June 30, 2010**   **Mar 31, 2010** 
**Canada – Western Canada**
          
Light crude oil and NGL (mbbls/day)
   23.0     23.0     23.5     22.5     23.4  
Medium Crude Oil (mbbls/day)
   25.4     25.3     25.7     25.1     25.3  
Heavy crude oil (mbbls/day)
   74.5     74.6     72.4     74.6     76.4  
Bitumen (mbbls/day)
   22.3     23.1     21.9     21.5     22.6  
Natural gas (mmcf/day)
   506.8     494.2     505.5     503.9     523.7  
**Canada – Atlantic Region**
          
Light crude oil (mbbls/day)
   46.7     41.3     50.8     45.0     49.9  
**China**
          
Light crude oil and NGL (mbbls/day)
   10.7     10.8     10.1     11.2     11.0    
 

 
   
 

 
   
 

 
   
 

 
   
 

 
 
**Total gross production (mboe/day)**
  ** ****287.1****  **  ** ****280.5****  **  ** ****288.7****  **  ** ****283.9****  **  ** ****295.9****  **  
 

 
   
 

 
   
 

 
   
 

 
   
 

 
 
**Average Gross Daily Production:**
  **Year Ended**   **Three Months Ended**    **Dec 31, 2009**   **Dec 31, 2009**   **Sept 30, 2009**   **June 30, 2009**   **Mar 31, 2009** 
**Canada – Western Canada**
          
Light crude oil and NGL (mbbls/day)
   22.8     22.4     23.0     21.7     24.2  
Medium Crude Oil (mbbls/day)
   25.4     24.8     24.8     25.6     26.3  
Heavy crude oil (mbbls/day)
   78.6     78.6     75.7     78.1     82.1  
Bitumen (mbbls/day)
   23.1     23.3     24.0     22.2     22.7  
Natural gas (mmcf/day)
   541.7     528.7     535.0     552.3     551.2  
**Canada – Atlantic Region**
          
Light crude oil (mbbls/day)
   55.2     43.8     29.0     65.9     82.6  
**China**
          
Light crude oil (mbbl/day)
   11.1     10.5     10.5     11.7     12.1    
 

 
   
 

 
   
 

 
   
 

 
   
 

 
 
**Total gross production (mboe/day)**
  ** ****306.5****  **  ** ****291.5****  **  ** ****276.2****  **  ** ****317.2****  **  ** ****342.0****  **  
 

 
   
 

 
   
 

 
   
 

 
   
 

 
 
 *AIF 2011*  *Page 15*
Table of Contents
The following tables show Husky’s netback analysis by product and area. The netbackanalysis has been revised relative to previous years to provide greater detail at the product level. Prior periods are restated to reflect current presentation. 

 

**Average Per Unit Amounts:**
  **Year Ended**   **Three Months Ended**    **Dec 31, 2011**   **Dec 31, 2011**   **Sept 30, 2011**   **Jun 30, 2011**   **Mar 31, 2011** 
**Light crude oil and NGL ($/bbl)**
          
Canada – Western Canada
          
Price received
   81.38     86.71     74.16     85.29     78.55  
Royalties
   17.04     19.98     14.77     17.20     15.52  
Production costs
   22.88     22.02     21.16     23.78     24.68    
 

 
   
 

 
   
 

 
   
 

 
   
 

 
 
Netback
   41.46     44.71     38.23     44.31     38.35    
 

 
   
 

 
   
 

 
   
 

 
   
 

 
 
Canada – Atlantic Canada
          
Price received
   112.11     114.65     110.50     115.39     107.95  
Royalties
   19.36     22.35     17.12     19.61     18.31  
Production costs
   8.75     8.54     9.82     9.00     7.67  
Transportation costs (1)
   1.52     1.59     1.62     0.97     1.72    
 

 
   
 

 
   
 

 
   
 

 
   
 

 
 
Netback
   82.48     82.17     81.94     85.81     80.25    
 

 
   
 

 
   
 

 
   
 

 
   
 

 
 
Canada – Total
          
Price received (1)
   105.33     107.59     102.69     110.83     100.50  
Royalties
   18.25     21.37     16.02     18.32     17.05  
Production costs
   13.49     13.47     13.44     13.64     13.43    
 

 
   
 

 
   
 

 
   
 

 
   
 

 
 
Netback
   73.59     72.75     73.23     78.87     70.02    
 

 
   
 

 
   
 

 
   
 

 
   
 

 
 
China
          
Price received
   110.49     115.55     109.76     111.85     105.25  
Royalties
   32.75     36.39     32.34     37.22     25.54  
Production costs
   8.17     9.18     10.41     7.38     6.34    
 

 
   
 

 
   
 

 
   
 

 
   
 

 
 
Netback
   69.57     69.98     67.01     67.25     73.37    
 

 
   
 

 
   
 

 
   
 

 
   
 

 
 
Company Total
          
Price received (1)
   102.31     105.02     99.40     106.68     98.13  
Royalties
   20.00     22.87     17.76     20.89     18.28  
Production costs
   12.70     12.83     12.98     12.62     12.37    
 

 
   
 

 
   
 

 
   
 

 
   
 

 
 
Netback
   69.61     69.32     68.66     73.17     67.48    
 

 
   
 

 
   
 

 
   
 

 
   
 

 
 
**Medium crude oil ($/bbl)**
          
Canada – Western Canada
          
Price received
   75.65     84.32     70.11     80.27     67.83  
Royalties
   14.13     15.24     13.58     15.24     12.41  
Production costs
   19.76     20.97     21.14     17.69     19.21    
 

 
   
 

 
   
 

 
   
 

 
   
 

 
 
Netback
   41.76     48.11     35.39     47.34     36.21    
 

 
   
 

 
   
 

 
   
 

 
   
 

 
 
**Heavy crude oil ($/bbl)**
          
Canada – Western Canada
          
Price received
   66.99     75.60     61.61     71.59     58.86  
Royalties
   8.83     9.47     8.09     9.88     7.86  
Production costs
   18.53     18.51     18.94     18.36     18.29    
 

 
   
 

 
   
 

 
   
 

 
   
 

 
 
Netback
   39.63     47.62     34.58     43.35     32.71    
 

 
   
 

 
   
 

 
   
 

 
   
 

 
 
**Bitumen ($/bbl)**
          
Canada – Western Canada
          
Price received
   64.34     73.24     58.70     68.62     55.41  
Royalties
   8.69     9.75     6.73     7.91     10.18  
Production costs
   19.01     19.76     18.43     19.31     18.45    
 

 
   
 

 
   
 

 
   
 

 
   
 

 
 
Netback
   36.64     43.73     33.54     41.40     26.78    
 

 
   
 

 
   
 

 
   
 

 
   
 

 
 
**Natural gas ($/mcf)**
          
Canada – Western Canada (2) 
          
Price received
   3.75     3.40     3.97     3.86     3.77  
Royalties
   0.18     0.23     0.17     0.19     0.13  
Production costs
   1.81     1.86     1.95     1.78     1.66    
 

 
   
 

 
   
 

 
   
 

 
   
 

 
 
Netback
   1.76     1.31     1.85     1.89     1.98    
 

 
   
 

 
   
 

 
   
 

 
   
 

 
 
 
(1) 
Transportation costs are shown separately from price in Canada – Atlantic Region. This cost category is netted against price when calculatingCanada Total and Company Total balances. 
(2) 
Includes sulphur sales and royalties. 

 *AIF 2011*  *Page 16*
Table of Contents
**Average Per Unit Amounts:**
  **Year Ended**   **Three Months Ended**    **Dec 31, 2010**   **Dec 31, 2010**   **Sept 30, 2010**   **Jun 30, 2010**   **Mar 31, 2010** 
**Light crude oil and NGL ($/bbl)**
          
Canada – Western Canada
          
Price received
   66.40     69.84     62.34     64.02     69.41  
Royalties
   14.49     11.62     14.08     14.89     17.38  
Production costs
   16.25     17.49     10.59     17.69     19.45    
 

 
   
 

 
   
 

 
   
 

 
   
 

 
 
Netback
   35.66     40.73     37.67     31.44     32.58    
 

 
   
 

 
   
 

 
   
 

 
   
 

 
 
Canada – Atlantic Canada
          
Price received
   82.16     89.65     79.43     79.49     81.10  
Royalties
   19.25     16.35     16.49     21.78     22.28  
Production costs
   10.33     11.43     10.48     11.20     8.45  
Transportation costs (1)
   1.55     1.32     1.32     1.83     1.72    
 

 
   
 

 
   
 

 
   
 

 
   
 

 
 
Netback
   51.03     60.55     51.14     44.68     48.65    
 

 
   
 

 
   
 

 
   
 

 
   
 

 
 
Canada – Total
          
Price received (1)
   79.01     85.30     76.46     76.12     78.72  
Royalties
   17.62     14.05     15.41     19.83     21.04  
Production costs
   12.56     14.13     10.35     13.86     12.23    
 

 
   
 

 
   
 

 
   
 

 
   
 

 
 
Netback
   48.83     57.12     50.70     42.43     45.45    
 

 
   
 

 
   
 

 
   
 

 
   
 

 
 
China (2)
          
Price received
   83.38     89.62     79.67     84.17     79.71  
Royalties
   19.11     21.86     17.32     18.48     18.67  
Production costs
   6.06     6.28     7.69     6.23     4.11    
 

 
   
 

 
   
 

 
   
 

 
   
 

 
 
Netback
   58.21     61.48     54.66     59.46     56.93    
 

 
   
 

 
   
 

 
   
 

 
   
 

 
 
Company Total
          
Price received (1)
   76.91     82.86     73.90     74.68     76.65  
Royalties
   17.87     15.69     15.91     19.34     20.45  
Production costs
   11.46     12.55     10.18     12.34     10.95    
 

 
   
 

 
   
 

 
   
 

 
   
 

 
 
Netback
   47.58     54.62     47.81     43.00     45.25    
 

 
   
 

 
   
 

 
   
 

 
   
 

 
 
**Medium crude oil ($/bbl)**
          
Canada – Western Canada
          
Price received
   64.92     65.75     60.88     63.90     69.30  
Royalties
   11.58     10.96     10.37     11.83     13.21  
Production costs
   16.46     15.30     15.91     17.98     16.71    
 

 
   
 

 
   
 

 
   
 

 
   
 

 
 
Netback
   36.88     39.49     34.60     34.09     39.38    
 

 
   
 

 
   
 

 
   
 

 
   
 

 
 
**Heavy crude oil ($/bbl)**
          
Canada – Western Canada
          
Price received
   58.91     58.82     56.96     56.18     63.31  
Royalties
   8.63     7.67     8.25     8.58     10.02  
Production costs
   15.77     16.63     15.91     15.58     14.94    
 

 
   
 

 
   
 

 
   
 

 
   
 

 
 
Netback
   34.51     34.52     32.80     32.02     38.35    
 

 
   
 

 
   
 

 
   
 

 
   
 

 
 
**Bitumen ($/bbl)**
          
Canada – Western Canada
          
Price received
   57.84     59.14     55.41     52.58     61.82  
Royalties
   8.51     7.54     9.30     9.06     8.21  
Production costs
   20.37     21.70     17.99     19.56     22.08    
 

 
   
 

 
   
 

 
   
 

 
   
 

 
 
Netback
   28.96     29.90     28.12     23.96     31.53    
 

 
   
 

 
   
 

 
   
 

 
   
 

 
 
**Natural gas ($/mcf)**
          
Canada – Western Canada (2) 
          
Price received
   3.92     3.62     3.54     3.51     4.99  
Royalties
   0.23     0.17     0.23     0.18     0.32  
Production costs
   1.76     1.70     2.01     1.66     1.70    
 

 
   
 

 
   
 

 
   
 

 
   
 

 
 
Netback
   1.93     1.75     1.30     1.67     2.97    
 

 
   
 

 
   
 

 
   
 

 
   
 

 
 
 
(1) 
Transportation costs are shown separately from price in Canada – Atlantic Region. This cost category is netted against price when calculatingCanada Total and Company Total balances. 
(2) 
Includes sulphur sales and royalties. 

 *AIF 2011*  *Page 17*
Table of Contents
**Average Per Unit Amounts:**
  **Year Ended**   **Three Months Ended**    **Dec 31, 2009**   **Dec 31, 2009**   **Sept 30, 2009**  **Jun 30, 2009**  **Mar 31, 2009** 
**Light crude oil and NGL ($/bbl)**
        
Canada – Western Canada
        
Price received
   54.60     65.44     59.93    51.48    42.01  
Royalties
   11.39     13.87     12.14    9.56    9.93  
Production costs
   17.15     18.44     11.14    19.41    19.72    
 

 
   
 

 
   
 

 
  
 

 
  
 

 
 
Netback
   26.06     33.13     36.65    22.51    12.36    
 

 
   
 

 
   
 

 
  
 

 
  
 

 
 
Canada – Atlantic Canada
        
Price received
   66.52     78.71     73.47    70.44    54.24  
Royalties
   16.34     18.51     17.32    19.04    12.64  
Production costs
   8.80     8.26     22.84    7.73    4.90  
Transportation costs (1)
   2.09     2.49     4.05    2.14    1.11    
 

 
   
 

 
   
 

 
  
 

 
  
 

 
 
Netback
   39.29     49.45     29.26    41.53    35.59    
 

 
   
 

 
   
 

 
  
 

 
  
 

 
 
Canada – Total
        
Price received (1)
   63.90     75.48     69.33    66.80    52.00  
Royalties
   14.78     16.83     14.95    16.74    11.85  
Production costs
   11.48     12.23     18.97    10.76    8.16    
 

 
   
 

 
   
 

 
  
 

 
  
 

 
 
Netback
   37.64     46.42     35.41    39.30    31.99    
 

 
   
 

 
   
 

 
  
 

 
  
 

 
 
China
        
Price received
   69.75     79.16     78.51    74.45    48.74  
Royalties
   12.01     17.88     15.33    11.59    4.15  
Production costs
   5.50     7.53     5.25    4.45    4.94    
 

 
   
 

 
   
 

 
  
 

 
  
 

 
 
Netback
   52.24     53.75     57.93    58.41    39.65    
 

 
   
 

 
   
 

 
  
 

 
  
 

 
 
Company Total
        
Price received (1)
   62.59     73.47     67.54    65.33    50.42  
Royalties
   14.53     17.07     15.09    16.09    11.23  
Production costs
   10.52     11.13     15.49    9.92    7.91    
 

 
   
 

 
   
 

 
  
 

 
  
 

 
 
Netback
   37.54     45.27     36.96    39.32    31.28    
 

 
   
 

 
   
 

 
  
 

 
  
 

 
 
**Medium crude oil ($/bbl)**
        
Canada – Western Canada
        
Price received
   56.37     65.78     61.28    58.32    40.68  
Royalties
   8.79     10.15     11.52    8.02    5.57  
Production costs
   15.50     14.81     15.58    14.83    16.77    
 

 
   
 

 
   
 

 
  
 

 
  
 

 
 
Netback
   32.08     40.82     34.18    35.47    18.34    
 

 
   
 

 
   
 

 
  
 

 
  
 

 
 
**Heavy crude oil ($/bbl)**
        
Canada – Western Canada
        
Price received
   52.54     61.55     59.21    54.22    35.80  
Royalties
   7.40     8.85     8.57    8.14    4.18  
Production costs
   13.56     14.90     13.29    12.22    13.76    
 

 
   
 

 
   
 

 
  
 

 
  
 

 
 
Netback
   31.58     37.80     37.35    33.86    17.86    
 

 
   
 

 
   
 

 
  
 

 
  
 

 
 
**Bitumen ($/bbl)**
        
Canada – Western Canada
        
Price received
   51.90     60.70     58.44    53.32    34.23  
Royalties
   7.10     14.07     6.70    5.65    1.67  
Production costs
   16.34     20.02     13.50    13.88    17.96    
 

 
   
 

 
   
 

 
  
 

 
  
 

 
 
Netback
   28.46     26.61     38.24    33.79    14.60    
 

 
   
 

 
   
 

 
  
 

 
  
 

 
 
**Natural gas ($/bbl)**
        
Canada – Western Canada (2) 
        
Price received
   3.84     3.97     2.83    3.25    5.30  
Royalties
   0.17     0.29     (0.11)   (0.16)   0.69  
Production costs
   1.59     1.38     1.77    1.59    1.59    
 

 
   
 

 
   
 

 
  
 

 
  
 

 
 
Netback
   2.08     2.30     1.17    1.82    3.02    
 

 
   
 

 
   
 

 
  
 

 
  
 

 
 
 
(1) 
Transportation costs are shown separately from price in Canada – Atlantic Region. This cost category is netted against price when calculatingCanada Total and Company Total balances. 
(2) 
Includes sulphur sales and royalties. 

 *AIF 2011*  *Page 18*
Table of Contents
**Producing and Non-Producing Wells**(1) (2) (3)********

***Productive Wells***

 
   **Oil Wells**   **Natural Gas Wells**   **Total**    **Gross**   **Net**   **Gross**   **Net**   **Gross**   **Net** 
**Canada**
            
Alberta
   4,607     3,792     5,883     4,371     10,490     8,163  
Saskatchewan
   6,753     5,797     1,416     1,293     8,169     7,090  
British Columbia
   200     58     304     264     504     322  
Newfoundland
   28     11     —       —       28     11    
 

 
   
 

 
   
 

 
   
 

 
   
 

 
   
 

 
    11,588     9,658     7,603     5,928     19,191     15,586    
 

 
   
 

 
   
 

 
   
 

 
   
 

 
   
 

 
 
**International**
            
China
   33     13     —       —       33     13    
 

 
   
 

 
   
 

 
   
 

 
   
 

 
   
 

 
 
**As at December 31, 2011**
   11,621     9,671     7,603     5,928     19,224     15,599    
 

 
   
 

 
   
 

 
   
 

 
   
 

 
   
 

 
 
**Canada**
            
Alberta
   4,484     3,580     5,770     4,407     10,254     7,987  
Saskatchewan
   6,582     5,488     1,446     1,311     8,028     6,799  
British Columbia
   204     59     283     242     487     301  
Newfoundland
   25     9     —       —       25     9    
 

 
   
 

 
   
 

 
   
 

 
   
 

 
   
 

 
    11,295     9,136     7,499     5,960     18,794     15,096    
 

 
   
 

 
   
 

 
   
 

 
   
 

 
   
 

 
 
**International**
            
China
   32     13     —       —       32     13  
Libya
   3     1     —       —       3     1    
 

 
   
 

 
   
 

 
   
 

 
   
 

 
   
 

 
    35     14     —       —       35     14    
 

 
   
 

 
   
 

 
   
 

 
   
 

 
   
 

 
 
**As at December 31, 2010**
   11,330     9,150     7,499     5,960     18,829     15,110    
 

 
   
 

 
   
 

 
   
 

 
   
 

 
   
 

 
 
**Canada**
            
Alberta
   4,281     3,395     5,834     4,480     10,115     7,875  
Saskatchewan
   5,818     4,789     1,395     1,261     7,213     6,050  
British Columbia
   203     58     253     214     456     272  
Newfoundland
   23     8     —       —       23     8    
 

 
   
 

 
   
 

 
   
 

 
   
 

 
   
 

 
    10,325     8,250     7,482     5,955     17,807     14,205    
 

 
   
 

 
   
 

 
   
 

 
   
 

 
   
 

 
 
**International**
            
China
   31     12     —       —       31     12  
Libya
   2     1     —       —       2     1    
 

 
   
 

 
   
 

 
   
 

 
   
 

 
   
 

 
    33     13     —       —       33     13    
 

 
   
 

 
   
 

 
   
 

 
   
 

 
   
 

 
 
**As at December 31, 2009**
   10,358     8,263     7,482     5,955     17,840     14,218    
 

 
   
 

 
   
 

 
   
 

 
   
 

 
   
 

 
 
***Non-Producing Wells***

 
   **2011**    **Oil Wells**   **Natural Gas Wells**   **Total**    **Gross**   **Net**   **Gross**   **Net**   **Gross**   **Net** 
Canada
   4,442     3,916     1,571     1,327     6,013     5,243  
Libya
   3     1     —       —       3     1    
 

 
   
 

 
   
 

 
   
 

 
   
 

 
   
 

 
    4,445     3,917     1,571     1,327     6,016     5,244    
 

 
   
 

 
   
 

 
   
 

 
   
 

 
   
 

 
 
 
(1) 
The number of gross wells is the total number of wells in which Husky owns a working interest. The number of net wells is the sum of the fractionalinterests owned in the gross wells. Productive wells are those producing or capable of producing at December 31, 2011. 
(2) 
The above table does not include producing wells in which Husky has no working interest but does have a royalty interest. At December 31, 2011,Husky had a royalty interest in 4,087 wells of which 1,246 were oil producers and 2,841 were gas producers. 
(3) 
For purposes of the above table, multiple completions are counted as a single well. Where one of the completions in a given well is an oil completion,the well is classified as an oil well. In 2011, there were 476 gross and 458 net oil wells and 942 gross and 729 net natural gas wells which were completed in two or more formations and from which production is not commingled.

 *AIF 2011*  *Page 19*
Table of Contents
***Landholdings***

 
   **Developed Acreage**    **Gross**   **Net**    (thousands of acres) 
**As at December 31, 2011**
    
**Western Canada**
  
Alberta
   4,594     2,908  
Saskatchewan
   878     699  
British Columbia
   187     147  
Manitoba
   19     2    
 

 
   
 

 
    5,678     3,756  
**Eastern Canada**
   58     20    
 

 
   
 

 
    5,736     3,776  
**China**
   17     7  
**Libya**
   7     2    
 

 
   
 

 
    5,760     3,785    
 

 
   
 

 
 
**As at December 31, 2010**
    
**Western Canada**
  
Alberta
   4,172     2,729  
Saskatchewan
   891     704  
British Columbia
   172     133  
Manitoba
   2     —      
 

 
   
 

 
    5,237     3,566  
**Eastern Canada**
   54     18    
 

 
   
 

 
    5,291     3,584  
**China**
   17     7  
**Libya**
   7     2    
 

 
   
 

 
    5,315     3,593    
 

 
   
 

 
 
**As at December 31, 2009**
    
**Western Canada**
  
Alberta
   4,100     2,692  
Saskatchewan
   856     672  
British Columbia
   168     128    
 

 
   
 

 
    5,124     3,492  
**Eastern Canada**
   54     18    
 

 
   
 

 
    5,178     3,510  
**China**
   17     7  
**Libya**
   7     2    
 

 
   
 

 
    5,202     3,519    
 

 
   
 

 
 
 *AIF 2011*  *Page 20*
Table of Contents
***Landholdings (continued)***

    **Undeveloped Acreage**    **Gross**   **Net**    (thousands of acres) 
**As at December 31, 2011**
    
**Western Canada**
    
Alberta
   5,353     3,930  
Saskatchewan
   1,654     141  
British Columbia
   1,037     774  
Manitoba
   3     1    
 

 
   
 

 
    8,047     4,846  
**Canada – Northwest Territories and Arctic**
   1,156     633  
**Canada – Atlantic Region**
   5,548     3,339    
 

 
   
 

 
    14,751     8,818  
**United States**
   1,076     398  
**China**
   990     484  
**Indonesia**
   1,628     1,213  
**Greenland**
   8,471     5,983    
 

 
   
 

 
    26,916     16,896    
 

 
   
 

 
 
**As at December 31, 2010**
    
**Western Canada**
    
Alberta
   4,801     3,407  
Saskatchewan
   1,712     1,522  
British Columbia
   1,020     747  
Manitoba
   4     1    
 

 
   
 

 
    7,537     5,677  
**Canada – Northwest Territories and Arctic**
   943     303  
**Canada – Atlantic Region**
   4,777     2,989    
 

 
   
 

 
    13,257     8,969  
**United States**
   1,100     484  
**China**
   990     990  
**Indonesia**
   1,940     1,595  
**Greenland**
   8,471     5,983    
 

 
   
 

 
    25,758     18,021    
 

 
   
 

 
 
**As at December 31, 2009**
    
**Western Canada**
    
Alberta
   4,941     3,523  
Saskatchewan
   1,571     1,384  
British Columbia
   996     739  
Manitoba
   4     1    
 

 
   
 

 
    7,512     5,647  
**Canada – Northwest Territories and Arctic**
   1,207     487  
**Canada – Atlantic Region**
   5,128     3,137    
 

 
   
 

 
    13,847     9,271  
**United States**
   1,707     422  
**China**
   1,970     1,970  
**Indonesia**
   1,940     1,595  
**Greenland**
   8,471     5,983    
 

 
   
 

 
    27,935     19,241    
 

 
   
 

 
 
**Significant Factors or Uncertainties Relevant to Properties with No Attributed Reserves**

The Company has a $376 million work commitment associated with its undeveloped land holdings in the Canadian Northwest Territories andArctic. In total, the Company has $549 million in exploration work commitments to be incurred over the next five years. Over the next 12 months, approximately 916,000 net undeveloped acres or less than 5% of the Company’s net undevelopedlandholdings in Canada will be subject to expiry. 

 *AIF 2011* *Page 21*
Table of Contents
Husky holds interests in a diverse portfolio of undeveloped petroleum assets in WesternCanada, the Atlantic Region and in several other areas (offshore Greenland, China and Indonesia, the United States and the Canadian North West Territories and Arctic). As part of its active portfolio management, Husky continually reviews theeconomic viability of its undeveloped properties using industry standard economic evaluation techniques and pricing and economic environment assumptions. Each year, as part of this active management process, some properties are selected for furtherdevelopment activities, while others are held in abeyance, sold, swapped or relinquished back to the mineral rights owner. There is no guarantee that commercial reserves will be discovered or developed on these properties. 

**Drilling Activity**

 
   **Year ended December 31**    **2011**   **2010**   **2009**    **Gross**   **Net**   **Gross**   **Net**   **Gross**   **Net** 
**Canada – Western Canada**
            
Exploration
            
Oil
   50     40     60     51     18     9  
Gas
   24     24     37     31     37     22  
Dry
   3     3     8     8     7     6    
 

 
   
 

 
   
 

 
   
 

 
   
 

 
   
 

 
    77     67     105     90     62     37    
 

 
   
 

 
   
 

 
   
 

 
   
 

 
   
 

 
 
Development
            
Oil
   880     765     815     722     315     278  
Gas
   57     42     73     53     122     61  
Dry
   4     4     10     9     7     7    
 

 
   
 

 
   
 

 
   
 

 
   
 

 
   
 

 
    941     811     898     784     444     346    
 

 
   
 

 
   
 

 
   
 

 
   
 

 
   
 

 
    1,018     878     1,003     874     506     383    
 

 
   
 

 
   
 

 
   
 

 
   
 

 
   
 

 
 
**Canada – Atlantic Region**
            
Development
            
Oil
   3     2.1     2     1.4     —       —      
 

 
   
 

 
   
 

 
   
 

 
   
 

 
   
 

 
 
**China**
            
Exploration
            
Dry
   —       —       —       —       1     0.5    
 

 
   
 

 
   
 

 
   
 

 
   
 

 
   
 

 
 
Development
            
Oil
   1     0.4     1     0.4     2     0.8  
Gas
   4     2.0     2     1.0     —       —      
 

 
   
 

 
   
 

 
   
 

 
   
 

 
   
 

 
    5     2.4     3     1.4     2     0.8    
 

 
   
 

 
   
 

 
   
 

 
   
 

 
   
 

 
 
 

**Service/Stratigraphic Test Wells**
  **2011**    **Gross**   **Net** 
Canada **–**Western Canada
   211     189.0  
Canada **–** Atlantic Region
   2     0.9  
China
   8     6.8  
***Current Activities***

 
   **Exploratory**   **Development**    **Gross**   **Net**   **Gross**   **Net** 
**Wells Drilling**(1)********
        
Canada **–**Western Canada
   9     8.5     27     24.5  
Canada – Atlantic Region
   —       —       —       —    
China
   —       —       1     0.5  
 
    **2011**    **Gross**   **Net** 
**Service/Stratigraphic Test Wells**(1)********
    
Canada
   5     3.0  
 
(1) 
Denotes wells that were being drilled at February 20, 2012. 

 *AIF 2011*  *Page 22*
Table of Contents
**Costs Incurred**

 
   **2011**    **Total**   **Western****Canada**   **Atlantic**